Rotary-type drill bits include both rotary drag bits and roller-cone bits. Conventional rotary drag bits, or fixed cutter bits, typically include one or more blades that extend from a face of the drag bit, at one end, towards an opposite end of the drag bit. These drag bits typically include one or more cutting elements coupled to one or more of the blades. These cutting elements are used to cut through an earth formation during drilling. Adjacently positioned blades typically form a passageway, or junkslot, therebetween which allows for drilling fluid with entrained materials, or formation cuttings, that have been cut from the formation to pass upwardly around the bit and into the borehole above.
Conventional roller-cone bits typically have three cones that are each independently rotatable with respect to the bit body that supports the cones through one or more bearing assemblies. Each cone is mounted onto an end of a respective leg. These cones typically include inserts or integrally formed teeth that are used to cut through a formation during drilling. The spaces provided between the teeth, or inserts, and between the legs of the roller-cone bit provide a passage for drilling fluid and formation cuttings to pass through and enter the borehole above the bit.
When drilling a hole with conventional drill bits, the formation cuttings, over time, generally adhere to, or “ball up” on, the surface of the drill bit. These cuttings tend to accumulate, mechanically and/or chemically, in any void, gap, or recess created between the various structural components of the bit. This phenomenon is particularly enhanced in formations that fail plastically, such as certain shales, mudstones, siltstones, limestones and other ductile formations. In some instances, these formation cuttings become mechanically packed within these voids, gaps, or recesses or even pits or trenches etched into the bit by erosion and abrasion during the drilling process. In some instances, these formation cuttings adhere to the drill bit surface via a chemical bond. For example, when the surface of a bit becomes water wet in certain shale formations, the bit surface and clay layers of the shale, or formation cutting, share common hydrogen electrons thereby producing a chemical bond between the bit surface and the formation cutting. A similar sharing of electrons is present between the individual sheets of the shale itself, thereby allowing formation cuttings to accumulate and chemically bond to other formation cuttings previously adhered onto the bit surface. Adhesion between the formation cuttings and the bit surface also occurs when the charge of the bit face is opposite the charge of the formation, thereby causing an attraction between the two.
From an operations standpoint, bit balling is evidenced by increased pump pressures as the flow pathway through the well bore annulus becomes blocked, reduced rates of penetration, blocked shaker screens, a required over-pull tension that occurs due to a restricted annulus when tripping pipe, and possible stuck pipe. Once bit balling is diagnosed, conventional methods of remediation are to increase the weight on the bit, add chemicals, and perhaps pull the drill pipe out of the hole to clean the bit and bottom hole assembly. For a water-based mud, a detergent may be added to the drilling mud to reduce the ability of the hydrated clay to stick to the bit and bottom hole assembly. Glycol may also be added at about 3% to 4% of system volume. However, these conventional remediation methods often fail to cure this problem.
Preventative measures against bit balling include applying an active charging method to the downhole tool, applying a nitriding method to the downhole tool, and applying a non-water wettable coating to the downhole tool. The active charging method involves application of an electro-negative charge to the downhole tool to repel negatively charged shale particles while drilling and is disclosed in Reissue Pat. No. RE. 29,151, entitled “Repulsing Clays on Drill Bits” and issued on Mar. 15, 1977 to McCaleb, and U.S. Pat. No. 5,509,490, entitled “EMF Sacrificial Anode Sub and Method to Deter Bit Balling” and issued on Apr. 23, 1996 to Paske et al. This method is easily demonstrated with simple lab equipment and is commercially applied in pile driving through shale formations. A corollary to this approach is that it allows for a water film to adhere to the steel, which forms at least a portion of the tool, and interpose between the steel of the tool and the shale cuttings. This active charging method has been shunned for downhole use due to the difficulty of adding a downhole charging system to actively impart a negative charge to one or more of the bottom hole assembly and drill bit.
The nitriding method has been used to impart a residual electro-negative charge to the surface of the steel bodied drill bits and is disclosed in U.S. Pat. No. 5,330,016, entitled “Drill Bit and Other Downhole Tools Having Electro-Negative Surfaces and Sacrificial Anodes to Reduce Mud Balling” and issued on Jul. 19, 1994 to Paske et al., and SPE 35110, entitled “Successful Field Application of an Electro-Negative ‘Coating’ to Reduce Bit Balling Tendencies in Water Based Mud” and published on March 1996. This method has been relatively successful in field application but involves the added heat treatment ranging from approximately 950° F. to approximately 1050° F., treatment time, and treatment expense involved in gas nitriding. Additionally, portions of the downhole tool and/or drill bit are masked off prior to the application of the gas nitriding, which involves additional time and expense. These portions include, but are not limited to, the portions of the tool or bit where the cutters, cutting elements, inserts, or teeth, are to be brazed.
The non-water wettable coating method aims to slicken the surface of the downhole tools and/or the drill bits and is disclosed in U.S. Pat. No. 6,450,271, entitled “Surface Modifications for Rotary Drill Bits” and issued on Sep. 17, 2002 to Tibbitts et al., and SPE 74514, entitled “Innovative Low-Friction Coating Reduces PDC Balling and Doubles ROP Drilling Shales With WBM” and published on February 2002. This method involves the use of one of the following surface treatments on the downhole tool or drill bit: Teflon®, fluoropolymer, urethanes, epoxies, or plastic filled ceramics. None of these solutions are currently being employed in oilfield drilling beyond their potential inclusion within commercial paint.
In summary, active negative charged systems work but are impractical in oil and gas drilling. Nitriding based negative charged coatings work but are encumbered by time, expense, and manufacturing compromises. “Slickening” methods are not commercially viable due to expense, difficulties of application, poor adhesion, poor erosion resistance, and/or failure to actually reduce balling.
The drawings illustrate only exemplary embodiments of the invention and are therefore not to be considered limiting of its scope, as the invention may admit to other equally effective embodiments.